INCORPORATING SEISMIC ATTRIBUTE VARIATION INTO THE PRE-WELL

PLACEMENT WORKFLOW

A CASE STUDY FROM NESS COUNTY, KANSAS, USA

by

MAZIN Y. ABBAS

B.S., King Fahad University of Petroluem and Minerals, 2004

A THESIS

submitted in partial fulfillment of the requirements for the degree

MASTER OF SCIENCE

Department of Geology

College of Arts And Sciences

KANSAS STATE UNIVERSITY

Manhattan, Kansas

2009

Approved by:

Major Professor

Matthew W Totten

Copyright

MAZIN Y. ABBAS

2009

Abstract

3D seismic surveys have become the backbone of many exploration programs

because of their high resolution and subsequent success for wildcat test wells. There are

occasions when the predicted subsurface geology does not agree with the actual geology

encountered in the drilled well. A case in point occurred during the drilling of several

wells based upon a 3D seismic survey in Ness County, Kansas, where the predicted

Cherokee Sand did not meet the expectations. By better understanding the subsurface

geologic features in the subject area, this study will attempt to answer the question “what

went wrong?”

Seismic attribute analysis workflow was carried out and the results were

correlated to the available geological and borehole data within the survey boundaries.

The objective of running this workflow was to describe facies variations within the

Cherokee Sandstone. Correlations between seismic attributes and physical properties

from well data were used to define these variations. Finally, Distributions of the seismic

facies were mapped to predict the distribution of potential reservoir rocks within the

prospect area.

iv

Table of Contents

List of Figures ................................................................................................................................. v

List of Tables ................................................................................................................................ vii

Acknowledgements ...................................................................................................................... viii

Dedication ...................................................................................................................................... ix

CHAPTER 1 - Introduction ............................................................................................................ 1

Background ................................................................................................................................. 1

Objective ..................................................................................................................................... 4

Methodology ............................................................................................................................... 4

CHAPTER 2 - Literature Review ................................................................................................... 5

Brief History ............................................................................................................................... 5

Geological Review ...................................................................................................................... 6

Upper Mississippian ................................................................................................................ 6

Cherokee Group ...................................................................................................................... 7

Stratigraphy ......................................................................................................................... 7

Depositional Environment .................................................................................................. 9

3D Seismic ................................................................................................................................ 10

CHAPTER 3 - Methodology ........................................................................................................ 13

Data Loading ............................................................................................................................. 13

Field Data .............................................................................................................................. 13

Previous Works Data ............................................................................................................ 16

Schlumberger Petrel .............................................................................................................. 21

Synthetic Seismograms ............................................................................................................. 21

Horizon Tracking and Surface Generation ............................................................................... 26

Seismic Attributes ..................................................................................................................... 30

CHAPTER 4 - Discussions ........................................................................................................... 33

CHAPTER 5 - Conclusions and Recommendations ..................................................................... 41

References Cited ........................................................................................................................... 43

v

List of Figures

Figure ‎1-1 Map location of the subject well .................................................................................. 1

Figure ‎1-2 Seismic cross section showing the doublet tracking ..................................................... 2

Figure ‎1-3 Isochron map showing Keith #1 well drill site at the thickest spot in the map............. 3

Figure ‎2-1 Distribution of Oil fields in Ness County .................................................................... 6

Figure ‎2-2 The relationship between the stratigraphy and a generalized type log in the area ....... 8

Figure ‎2-3 A southwest-northeast stratigraphic cross section from Kearny to Ellis Counties ...... 9

Figure ‎2-4 Chronology of seismic instrumentation and methods ................................................ 12

Figure ‎2-5 Percentage of seismic activity involving various technologies .................................. 12

Figure ‎3-1 ASCII header of Wierman 3D Seismic survey loaded to Petrel project ..................... 14

Figure ‎3-2 Coral Coast’s seismic cross section #1 showing the target sand ................................ 17

Figure ‎3-3 Coral Coast’s seismic cross section #2 showing the target sand ................................ 18

Figure ‎3-4 Coral Coast’s isochron map #1 ................................................................................... 19

Figure ‎3-5 Coral Coast’s isochron map #2 ................................................................................... 20

Figure ‎3-6 Wells tied to the seismic in a cross section view ........................................................ 22

Figure ‎3-7 Wavelet profile window for Keith #1 ......................................................................... 24

Figure ‎3-8 Wavelet profile window for Wanda Judeen ................................................................ 24

Figure ‎3-9 Synthetics interpretation window for Keith #1 ........................................................... 25

Figure ‎3-10 Synthetics interpretation window for Wanda Judeen................................................ 25

Figure ‎3-11 Interpretation window shows the composite seismic line cross section ................... 26

Figure ‎3-12 Stone Corral and Pawnee Limestone Surfaces.......................................................... 28

Figure ‎3-13 Cherokee and Mississippian Surfaces ....................................................................... 28

Figure ‎3-14 Comparison between the first set of isochron maps.................................................. 29

Figure ‎3-15 Comparison between the second set of isochron maps ............................................. 29

Figure ‎3-16 Relative AI and Average Energy maps 15 ms around Mississippian surface ........... 31

Figure ‎3-17 Attenuation and RMS Amplitude maps 15 ms around Mississippian surface .......... 32

Figure ‎4-1 Zoomed amplitude and energy maps around Keith #1 area ........................................ 33

vi

Figure ‎4-2 Zoomed relative AI and energy maps around Keith #1 area ...................................... 34

Figure ‎4-3 Zoomed attenuation map around Keith #1 area .......................................................... 35

Figure ‎4-4 Extended average energy map covering all wells within the survey .......................... 37

Figure ‎4-5 Extended RMS amplitude map covering all wells within the survey ......................... 38

Figure ‎4-6 Extended relative AI map covering all wells within the survey ................................. 39

Figure ‎4-7 Extended attenuation map covering all wells within the survey ................................. 40

Figure ‎5-1 combination of the four maps highlighting a possible target ...................................... 42

vii

List of Tables

Table ‎1-1 Suggested methods ......................................................................................................... 4

Table ‎3-1 Data available in each well ........................................................................................... 15

Table ‎3-2 Digital well logs available ............................................................................................ 15

Table ‎3-3 The formation tops markers for each well. The unit is feet MD .................................. 16

Table ‎3-4 Functionalities available in Petrel ............................................................................... 21

Table ‎3-5 The interpretation of each of the formation tops .......................................................... 23

Table ‎3-6 The picked time depths for formation tops. The unit is milliseconds .......................... 23

Table ‎3-7 Attributes descriptions .................................................................................................. 30

viii

Acknowledgements

Many thanks to Saudi Aramco for sponsoring my studies at KSU. They really gave me

the opportunity to learn and achieve many of the things I was aiming for and more.

Thanks to geology department faculty, students and staff at KSU for their help and

support during the last two years I have been there. Special thanks to Dr. Matthew Totten, Dr.

Abdelmoneam Raef, Dr. Matthew Brueseke, and Dr. Allen Archer for all the knowledge I earned

from them.

Special thanks to Susan Nissen for her help in setting up the project. Also, many thanks

go to Coral Coast Petroleum for providing the data for this study and Schlumberger for donating

academic license for their software.

ix

Dedication

I want to dedicate this work for the love of my life Sarah my wife. For her patience,

support and encouragement during the last two years. Without her this work would have been

impossible for me. So, thank you Sarah …

1

CHAPTER 1 - Introduction

Background

3D seismic surveys have become the backbone of many exploration programs because of

their high resolution and subsequent success for wildcat test wells. There are occasions when the

predicted subsurface geology does not agree with the actual geology encountered in the drilled

well, begging the question “what went wrong?”

In 2003 Coral Coast Petroleum started drilling a wildcat well, Keith #1, with a Cherokee

Sandstone target in northeastern Ness County, Kansas. Figure 1-1 shows the location of Keith #1

which is Section 18, Township 16 South, Range 22 West (S18-T16S-R22W). The well produced

162 barrels before it was plugged as dry and abandoned.

Figure ‎1-1 Map location of the subject well 1

The prospect was based upon a 3D seismic survey, which predicted the presence of an

extensive sandstone reservoir. From discussions with the operator, the potential reservoir was

1 Modified from (Kansas Geological Survey, 2009)

2

identified based on two criteria. First, occurrence and tracking of the doublet signal reflection at

the base of the Cherokee formation and right at the top of Mississippian formation (Figure 1-2).

The second criterion was the isochron (time) thickness at that area (Figure 1-3). However, the

predicted sand body was not encountered as expected. The results of a drillstem test encouraged

the operator to run production casing and complete the well, however very little oil was produced

and the well was subsequently abandoned.

Figure ‎1-2 Seismic cross section showing the doublet tracking

3

Figure ‎1-3 Isochron map showing Keith #1 well drill site at the thickest spot in the map

4

Objective

The main objective of this study is to investigate why using the seismic survey did not

give the positive results expected in Keith #1. In addition, this study tries to determine whether

additional geophysical interpretation techniques, exclusive of reprocessing the seismic dataset,

would have prevented this dry hole with its subsequent large investment of resources.

Furthermore, establishing a workflow that avoids the false positive indicators used in this

prospect will be of benefit to other operators in this region.

Methodology

As a starting point for this project, data collected from previous work on the Keith

Prospect was loaded and reviewed. Collected data include; 3D seismic survey, well logs, maps

and any reports or documentations written for the subject wells. For the purpose of this project,

Petrel software from an academic license granted by Schlumberger was used to accomplish the

workflow of suggested methods for this project (Table 1-1). After loading the available data into

Petrel, quality checking and verification of the data was carried out. Synthetic seismograms

using the acoustic log collected from the available wells were constructed. The synthetic

seismograms were compared against the seismic survey and well top markers which identifies

the distribution of each formation within the seismic data. Then, with the help of the synthetics

seismograms overlain on top of the seismic sections, the identified formation tops were tracked

and interpreted throughout the survey. This generated the basic structure horizons which were

used to generate their relative surfaces maps. The next step was to generate the seismic attributes

maps for all surfaces. Finally, seismic attributes analysis was carried out as the last step before

the results were drawn out.

Table ‎1-1 Suggested methods

Step Method description

Step 1 Create new project in Petrel, load and quality check available data

Step 2 Synthetic seismograms - generation and interpretation

Step 3 Horizon tracking and surface generation

Step 4 Seismic attributes generation

Step 5 Seismic attributes analysis

5

CHAPTER 2 - Literature Review

Brief History

Ness County is located in the western half of the State of Kansas. The eastern part of the

county lies on the western flank of the central Kansas uplift. Strucker No. 1 was the first

exploratory well in Ness County, which is located at SE NW of S1-T17S-R26W, in 1922. The

well was abandoned at total depth of 3,500 ft. In 1929, Aldrich No. 1 was drilled in NE SW of

S7-T18S-R25W. The well was drilled on the Beeler anticline and oil was found on the top of the

“Mississippi Lime” which was encountered at 4,422 ft. Initial production of Aldrich No. 1 was

100 bpd (Carpenter, 1945).

In 2006, the number of producing wells in Ness County reached 891 wells with total

production of 1,774,405 bbls of oil and 110,843 mcf of gas for that year. The majority of these

wells are producing from Mississippian zones (Kansas Geological Survey, 2009). The pinching

out of the “Mississippi Lime” towards the northeast of the Ness County and the related fold

towards the west half of the county are the two principle geologic conditions for the presence of

oil accumulation in the county (Carpenter, 1945). In this area production occurs primarily within

Pennsylvanian-aged sandstone (Cherokee). Figure 2-1 shows the distribution of oil fields in Ness

County.

6

Figure ‎2-1 Distribution of Oil fields in Ness County 2

Geological Review

Upper Mississippian

The Upper Mississippian Series in Kansas consists predominantly of beds of limestone

and dolomite, with interspersed beds of sandstone and shale, and minor amounts of chert.

Rocks of the Meramecian Stage lie disconformably on Osagian rocks, but in northeastern

and southwestern Kansas the disconformity is unclear. It consists of Warsaw Limestone, Salem

Limestone, St. Louis Limestone and Ste. Genevieve Limestone. The upper formations consist

mostly of granular, sandy, oolitic and fossiliferous limestone, but lower formations contain

interbedded dolomite or are mainly dolomite and silty, dolomitic limestone containing variable

quantities of chert. Meramecian rocks, except for the Ste. Genevieve Limestone, probably

extended originally throughout Kansas but were eroded from much of the State before

Pennsylvanian deposits were formed (Zeller, 1968).

2 Modified from (Kansas Geological Survey, 2009)

7

The Warsaw Limestone is 30 to 40 feet thick in the Forest City and Salina basins and 250

feet thick in the central part of the Hugoton embayment. The Salem Limestone conformably

overlies the Warsaw Limestone. Its thickness is about 50 feet in the deepest part of the Salina

basin, where it underlies Pennsylvanian rocks, and in the Forest City basin, where it underlies the

St. Louis Limestone. In the Hugoton embayment, it is about 200 feet thick. Although restricted

to basin areas, the St. Louis Limestone is more widely distributed. It is not recognized in the

Salina basin. Maximum thickness in the Forest City basin is about 50 feet and in the Hugoton

embayment about 200 feet. The Ste. Genevieve Limestone, which lies disconformably beneath

Chesteran rocks but seemingly conformable on the St. Louis Limestone, is widespread in the

Hugoton embayment, but is not recognized in the Salina basin. Its thickness is more than 200

feet in the Hugoton embayment (Zeller, 1968).

Important unconformities separate the rocks of the Chesteran Stage from Pennsylvanian

rocks above and Meramecian beds below. Chesteran rocks are unknown in south-central and

northern Kansas. In the subsurface of southwestern Kansas, Chesteran rocks are confined to

deeper parts of the Hugoton embayment in Morton, Stevens, Seward, Meade, Grant, Haskell, and

parts of adjacent counties. Thickness ranges from 0 feet to more than 300 feet near the Oklahoma

state line. In Kansas Chesteran rocks are thin or absent on several structural highs (Zeller, 1968).

Cherokee Group

Stratigraphy

The Desmoinesian Stage of the Middle Pennsylvanian Series represents the initial period

of deposition in the area following the Mississippian unconformity. The Cherokee Group is the

lowest division of the Desmoinesian Series and is composed mostly of shale and sandstone, with

minor amounts of limestone. Thickness of the Cherokee Group in the area ranges from 5 to 200

ft (Stoneburner, 1982).

The Marmaton Group conformably overlies the Cherokee Group. The group is divided

into four limestone formations with each one separated by a formation of shale. The lower two

limestone units are the Fort Scott and Pawnee limestone and the shale separating them is the

Labette shale formation. These formations represent changes from clastic to carbonate deposition

in the area (Stoneburner, 1982).

8

The Fort Scott Limestone is primarily cream to tan to light-gray macrocrystalline

limestone characterized by local occurrences of fusulinids, crinoids stems, and rare

developments of oolitic limestone. The thickness of the formation generally ranges from 8 to 12

ft. The Labette Shale Formation ranges from 15 to 50 ft in thickness and consists of gray,

reddish-brown and maroon shale with consistent dark-gray carbonaceous shale present in the

upper part. The lower section is typically micaceous and silty, with local development of

sandstones. The Pawnee Limestone conformably overlies the Labette Shale. The lithology of the

formation is predominantly chert, with some limestone and dolomite. The thickness of the

Pawnee Limestone is ranging from 30 to 70 ft (Stoneburner, 1982). Figure 2-2 illustrates the

stratigraphy in Ness County based upon well log signatures.

Figure ‎2-2 The relationship between the stratigraphy and a generalized type log in the area 3

3 Modified from (Stoneburner, 1982)

9

Depositional Environment

In western Kansas, the Cherokee Group overlies rocks ranging in age from Precambrian

to Atokan. The Cherokee was deposited in environments that are transitional from continental to

marginal marine as the Hugoton Sea transgressed the Mississippian unconformity onto the

Central Kansas uplift (Cuzella, 1991).

Figure 2-3 shows the stratigraphic relations of Cherokee rocks to older and younger units.

The area of study is roughly in the region between wells 9 and 10 in the cross section. In the

southwest the Cherokee strata appear to be thicker than towards the Central Kansas Uplift. Near

the uplift the Cherokee group is mainly composed of clastic material derived from the eroding

Central Kansas uplift. Away from the uplift in the southwest it consists mainly of limestone and

black shale (Merriam, 1963).

Figure ‎2-3 A southwest-northeast stratigraphic cross section from Kearny to Ellis Counties 4

4 Modified from (Merriam, 1963)

10

Sandstones are deposited along the Mississippian unconformity, which is defined by a

tilted sequence of alternating resistive rocks and shale, and underlying the clastic sequences

where the attitude of the unconformity controls the trend and distribution of the sandstones. The

result is a series of escarpments and valleys, where later streams have cut into less resistant strata

(Stoneburner, 1982).

Analysis of Gamma ray logs collected around the study area showed characteristics of

channel sandstones. The sandstones displayed an increase upward in radioactivity which

indicates that the lower portion of the sand has cleaner and coarser sand at the base, and fines

upward in grain size. Based on Walter’s Law, this fining up sequence corresponds to the lateral

sequence across a channel, from shales and siltstones of the flood plain facies, to fine-grained

sandstones in the point-bar facies, to coarser grained sandstones and conglomerates in the

channel facies (Stoneburner, 1982).

3D Seismic

In 1917, Reginald Fessenden was issued the first (U.S.) patent entitled “Methods and

apparatus for locating ore bodies”. His method was based on the application of seismic waves

similar to acoustic waves in water to detect icebergs. This was among many inventions which

Fessenden worked on after the sinking of Titanic by an iceberg in 1912. Since then and until

recent history and development of the common-midpoint, vibroseis, digital processing and 3-

Dimensional techniques, the amount of geological information extracted from seismic data has

greatly improved (Figure 2-4 and Figure 2-5). Exploration Seismology Technology uses

artificially generated elastic waves to define locations of mineral deposits, and has become the

backbone of many exploration programs because of its high resolution and subsequent success.

Locating mineral deposits such as hydrocarbons, ores, water and geothermal reservoirs is not the

only use of this technology today; it also obtains geological information that aid in better

understanding of different engineering projects. When the information extracted from seismic

data is integrated with other available geophysical and geological data, this can supply new

knowledge about the structure and distribution of rock types. However, and as known in this

field, the technology by itself cannot guarantee successful results even if integrated with other

information. This can be related to the wide range of possible interpretations that could be

extracted from the data, where each possibility is dependent on the approach used to interpret the

11

data. Ultimately, the best interpretation is the one based on a consistent approach which

integrates the latest and most developed workflows (Sheriff and Geldart, 1982; 1983).

In the last several years, the relationship between specific attributes of the seismic data

and reservoir development were recognized. Many of these seismic attributes are now used by

geoscientists to map geological features. Some attributes can be indicators of changes in

lithology. Examples of such attributes include seismic amplitude, envelope, root mean square

(RMS) amplitude, spectral magnitude, acoustic impedance and elastic impedance. Layer

thicknesses can also be indicated by seismic attributes, such as peak-to-trough thickness, peak

frequency and bandwidth. Other seismic attributes such as coherence, amplitude gradients, dip-

azimuth and curvature can be used to indicate seismic textures and morphology (Chopra and

Marfurt, 2008).

Attributes can derive additional information from seismic data that can be used as a

baseline for quantitative and/or qualitative interpretations. Quantitative interpretation means that

seeking numerical estimations of properties throughout the seismic dataset. On the other hand,

qualitative interpretation means that defining geobodies reflecting similar physical properties. In

both cases, there are two important steps for a successful workflow that could facilitate making

exploration or development decisions. First is the careful selection of which seismic attributes

will best serve the objective. Second is testing the results against available existing knowledge

and models. Therefore, integration of geological models and well data to information extracted

from seismic attributes can establish more acceptable and reliable interpretation workflows.

(Hart, 2002).

12

Figure ‎2-4 Chronology of seismic instrumentation and methods 5

Figure ‎2-5 Percentage of seismic activity involving various technologies 6

5 Modified from (Sheriff and Geldart, 1982; 1983)

6 Modified from (Sheriff and Geldart, 1982; 1983)

13

CHAPTER 3 - Methodology

Data Loading

The first step of any study is to collect all available data and quality check the collected

data before and after loading the project. As mentioned above, Schlumberger Petrel software was

used throughout this study. The collected data includes data from the field and data related to

previous work done by the company. Field data of course include; the 3D seismic survey, well

logs from Keith #1, and all other well data available within the limits of the survey boundaries.

On the other hand, data from previous work include; maps and reports generated by for the

purpose of the subject well.

Finally, a new project in Petrel was created and all related data was loaded and quality

checked to verify the validity of the data.

Field Data

In 2002, Coral Coast Petroleum conducted the Wierman Field 3D seismic survey. The

survey was acquired with 2.0 millisecond sampling rate for 136 inlines running west to east and

61 crosslines running south to north. Its width is around 0.9 miles from the west edge of S18-

T16-R22W, and approximately 2.1 miles long from slightly above the north edge of S18-T16-

R22W. The survey was received as a standard .SEGY file. Other information about the seismic

survey include; the Seismic Reference Datum (SRD) of 2700 ft and a replacement velocity of

9000 ft/s. The projection system used to load the survey was NAD27 Kansas State Planes,

Southern Zone, US Foot. The loading parameters for the loaded seismic survey is summarized in

the following snapshot of the ASCII header that was extracted after loading to Petrel

14

Figure ‎3-1 ASCII header of Wierman 3D Seismic survey loaded to Petrel project

Other field data collected include data available for wells falling within the limits of the

survey boundaries. There are 4 wells that had digital well log data. The 4 wells are Keith #1,

Keith #2, Wanda Judeen and W&K #1. Well data includes; location, elevation, status, logging

data, formation tops markers and the total depth of the well (TD). There are other wells within

the area but no information known for them except for locations, status, raster logs and formation

tops. Table 3-1 lists all wells within the subject area. Table 3-2 and Table 3-3 list available data

for the above wells.

15

Table ‎3-1 Data available in each well

Well Name Elevation Status TD Well Logs Tops

Keith #1 2455 KB Oil, plugged &

abandoned

4520 Digital Yes

Keith #2 2456 KB Plugged &

abandoned

4510 Digital Yes

Wanda Judeen 2445 KB Dry, plugged

& abandoned

4530 Digital Yes

W&K #1 2430 KB Dry, plugged

& abandoned

4530 Digital Yes

Squires 1 2439 KB Dry, plugged

& abandoned

4597 TIFF Yes

Snodgrass 1 2442 KB Dry, plugged

& abandoned

4466 TIFF Yes

C. Snodgrass 2456 KB Dry, plugged

& abandoned

4510 TIFF Yes

Wierman 1 2432 GL Dry, plugged

& abandoned

4450 TIFF N/A

Wierman 2 2411 TOPO Approved to

Drill

4400 N/A N/A

Table ‎3-2 Digital well logs available

Well Name Sonic Gamma Density Porosity Resistivity SP

Keith #1 Yes Yes Yes Yes Yes Yes

Keith #2 Yes Yes N/A Yes Yes Yes

Wanda Judeen Yes Yes Yes Yes Yes Yes

W&K #1 Yes Yes Yes Yes Yes Yes

16

Table ‎3-3 The formation tops markers for each well. The unit is feet MD

Well Name Stone

Corral

Heebner

Shale

Pawnee

Lime

Fort

Scott

Cherokee Mississippian

Keith #1 1783 3847 4244 4344 4356 4495

Keith #2 N/A 3842 4259 4335 4362 4487

Wanda Judeen 1801 3848 4238 4345 4361 4529

W&K #1 1779 3825 4222 4326 4350 4452

Squires 1 1785 3822 N/A N/A 4302 N/A

Snodgrass 1 N/A 3814 N/A 4229 4305 4417

C. Snodgrass 1783 3841 4257 N/A 4370 4462

Previous Works Data

Data from previous work include any information reported by Coral Coast Petroleum.

These data were collected in forms of interpretations, maps or reports. Previous works data are

significant for understanding how the company professionals interpreted field data and

eventually made their decisions towards drilling. So far, previous works released for this study

from the company include; two seismic cross sections (Figure 3-2 and Figure 3-3) and two

isochron maps (Figure 3-4 and Figure 3-5). Careful analysis of these maps and cross sections

show that the drillsite was chosen based on two criteria. First criterion was the isochron thickness

at that area. Thickening of the Cherokee section often occurred along the paleolows in the

Mississippian, where sand typically is deposited. The second criterion was the occurrence and

tracking of the doublet signal reflection at the base of the Cherokee formation and right at the top

of Mississippian formation. Apparently, the company professionals were tracking these doublets

under the assumption that they might reflect a change in the lithology. Moreover, the doublets

locations in the cross section tied with the thickness maps under thicker areas which might gave

more incentive to decide the positioning of the well.

17

Figure ‎3-2 Coral Coast’s seismic cross section #1 showing the target sand

18

Figure ‎3-3 Coral Coast’s seismic cross section #2 showing the target sand

19

Figure ‎3-4 Coral Coast’s isochron map #1

20

Figure ‎3-5 Coral Coast’s isochron map #2

21

Schlumberger Petrel

Petrel is a PC-based software application which covers a wide range of workflows from

seismic interpretation to reservoir simulation. The basic principle of Petrel integrated solution is

that geophysicists, geologists and reservoir engineers can move just across domains within one

software application, rather than moving between different software applications. One of the key

benefits of integrated solutions such as Petrel is the elimination of import and export problems.

Moreover this type of solutions promotes and encourages collaboration between different

domains7. The wide range of functionality in Petrel covers:

Table ‎3-4 Functionalities available in Petrel 8

3D visualization Facies Modeling

Well correlation Petrophysical Modeling

Classification and Estimation (Neural Net) Data Analysis

Creation of synthetic seismograms Uncertainty Analysis

Seismic attributes Fracture Modeling

Geobody Interpretation Volume Calculation

2D & 3D seismic interpretation and modeling 3D well design

Seismic volume rendering and extraction Streamline simulation

3D mapping ECLIPSE Simulation

3D grid modeling for geology and reservoir

simulation

Simulation post-processing

Velocity Modeling (Domain Conversion) Remote Simulation Run submission

Well log upscaling Plotting

To learn more about Petrel: SLB Petrel9

Synthetic Seismograms

The first step in every seismic interpretation project is to start with the challenge of tieing

seismic reflections to formation markers from well logs via synthetic seismograms. The main

7 Information gathered from Petrel help files

8 Modified from Petrel help files

9 http://www.slb.com/content/services/software/geo/petrel/index.asp?

22

input for synthetics is the time-depth (T-D) relationship or chart. T-D charts can be generated

from either a check-shots survey or an acoustic (sonic) log. In this case study, there were no

check-shots available in the area within the limits of Wierman seismic survey boundaries. So, T-

D charts were generated from the sonic logs available with the wells. Figure 3-6 shows a cross

section view of the wells displayed on the seismic after tieing.

Figure ‎3-6 Wells tied to the seismic in a cross section view

A seismic-to-synthetics tie was achieved after generating synthetic seismograms by

convolving an extracted seismic wavelet with the normal incidence reflectivity at each of the

wells. Only two of the wells resulted in acceptable synthetics. Those wells are; Keith #1 and

Wanda Judeen. Figure 3-7 and Figure 3-8 show the generated wavelets profiles for each well

respectively. The profiles show zero phase shift and normal polarity for both wavelets. The

wavelets envelop spectrums show a dominant frequency of about 48 Hz. Since the average

velocity in this area is around 8000 ft/s, the dominant wavelength can be calculated to enable an

estimation of the temporal resolution limit of the seismic data. After that, radial well seismic had

been extracted around each well which are important in order to match the synthetic to the

seismic data. Finally, a complete synthetics package for each well was generated as a result of

the Synthetic Process.

23

The synthetics normally do not exactly match character-wise to the seismic. This is when

the synthetic interpretation step is required. In order to match the generated synthetic

seismograms to the seismic trace, minor stretching and squeezing is required until an acceptable

level of match is reached. Adjustments of the synthetics need to be done with the help of the

formation tops and the change in acoustic impedance value. If the acoustic impedance value at a

specific formation is going from low to high that means the formation top should match a peak.

And, if the acoustic impedance value is going from high to low then the formation top should

match to a trough. Table 3-5 lists the formation tops were picked and their respective change in

acoustic impedance and reflections. The last step in synthetics interpretation is to check the

quality of the match. The normalized correlation coefficient (-1<= values <=1) between the

synthetic trace and the real seismic value can be used as a match-quality indicator. The higher

the value of the correlation coefficient the better quality of the match and the opposite is true.

Based on that, the correlation coefficient value after the interpretation showed 0.3. This value

can be considered as a good enough match for tieing seismic events to the corresponding

geological tops. The reason for the low correlation coefficient value could be related to T-D

relationships. The fact that T-D relationships for the wells were generated from the available

sonic log and not from a check-shots survey may contributed to this result. Figures 3-9 and 3-10

show the final synthetics seismograms interpreted for each of the wells and Table 3-6 shows the

time depth for the well tops in each well.

Table ‎3-5 The interpretation of each of the formation tops

Formation top Change in acoustic impedance Reflection

Stone Corral Low to high Peak

Pawnee Limestone High to low Trough

Cherokee Group High to low Trough

Mississippian System Low to high Peak

Table ‎3-6 The picked time depths for formation tops. The unit is milliseconds

Well Name Stone Corral Pawnee Lime Cherokee Mississippian

Keith #1 490.45 864.52 876.69 903.60

Wanda Judeen 492.07 869.85 880.86 905.47

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Figure ‎3-7 Wavelet profile window for Keith #1

Figure ‎3-8 Wavelet profile window for Wanda Judeen

25

Figure ‎3-9 Synthetics interpretation window for Keith #1

Figure ‎3-10 Synthetics interpretation window for Wanda Judeen

26

Horizon Tracking and Surface Generation

After the synthetic interpretations were reached, the formation surfaces were tracked and

identified throughout the entire seismic volume. To start with, a composite line of the seismic

volume running through all wells was extracted. Then, the wells and their synthetics traces were

displayed on top of it. In addition, the well formation tops were displayed. The Seismic

Interpretation process in Petrel was used to complete this task. The composite line was displayed

in an interpretation window in the time domain (Figure 3-11). The benefit of using a composite

line section at the start of the horizon tracking is to guide the later inline and xline tracking in

areas where well controls are absent. After the composite line tracking completed, regular inlines

and xlines were tracked with an increment of 5.

Initially, each of the horizons was tracked using the 2D Seeded Auto-tracking function.

Next, 3D Auto-tracking function was used to track all the points within the seismic volume.

Finally, Manual Tracking function was used in some areas where auto-tracking could not track

the events anymore. The outcomes of this process would be the generation of the respective

horizon of each formation marker that was tracked.

Figure ‎3-11 Interpretation window shows the composite seismic line cross section

27

The next step was to generate the surfaces for each of the tracked horizons respectively.

Make/Edit Surface process in Petrel was used in this step. In general, the process takes a horizon

as an input, the algorithm used to generate the surface and the specific boundaries for the surface.

The algorithm used for all the surfaces was the Kriging (Petrel 2008) and the boundaries were

automatically set from the input horizons. Figure 3-12 shows the maps for the Stone Corral

surface on the left and the Pawnee Limestone surface on the right. Figure 3-13 shows the maps

for the Cherokee Group surface on the left and the Mississippian surface on the right. All the

surfaces maps show the locations of the wells. Through the rest of this study the focus will be on

the Cherokee and the Mississippian surfaces.

To contrast the interpretation in this study with the previous interpretation work, two

isochron maps were generated then compared to the ones received from the company. It is

unlikely that two different interpretations would be identical, but they should agree with each

other to an acceptable degree. Before making these comparisons, one point needs to be clarified.

As mentioned in the geological review section, the Fort Scott limestone is the lowest member of

the Marmaton Group which lies above the Cherokee group. The thickness of the Fort Scott

ranges between 8 to 12 feet. So, it is not unusual that the two tops are interchangeably used in

some cases. With this small difference in mind, the first isochron map was for the time thickness

between the Stone Corral and the Fort Scott surfaces. This map was compared with the time

thickness map between the Stone Corral and the Cherokee surfaces generated for this study. The

second was for the time thickness between the Fort Scott and the Mississippian surfaces. This

was compared with the time thickness map between the Cherokee and Mississippian surfaces

generated for this study. Figure 3-14 shows a reasonable match between the first two maps, and

Figure 3-15 shows a reasonable agreement between the other two maps.

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Figure ‎3-12 Stone Corral and Pawnee Limestone Surfaces

Figure ‎3-13 Cherokee and Mississippian Surfaces

29

Figure ‎3-14 Comparison between the first set of isochron maps

Figure ‎3-15 Comparison between the second set of isochron maps

30

Seismic Attributes

The objective of running the seismic attributes workflow was to come up with qualitative

results that can be correlated with the geological and borehole data, and ultimately determine

why the original interpretation was incorrect. This was driven by the fact that the drilling of the

Keith #1 was based on the potential identification on an extensive sand body at that location. The

geological information needed from running this workflow includes; lithological changes,

porosity indications, hydrocarbon indications and fluid content and movement. The seismic

attributes can be extracted along a certain surface, a window interval around the surface or can

be extracted for the whole seismic volume. Window attributes are helpful in this case because

our target lies in the lower interval of the Cherokee Group. The range of the window, 15

milliseconds around the Mississippian surface, was determined using well logs. Gamma, sonic,

porosity and resistivity logs from Keith #1 indicated that the lower Cherokee sand lies within the

10 milliseconds interval above the top of the Mississippian surface. Therefore, the 15

milliseconds around the Mississippian surface represent 5 milliseconds below the surface and 10

milliseconds above it.

Table 3-7 lists the seismic attributes used in this workflow with a description and the

reflected interpretation for each one.

Table ‎3-7 Attributes descriptions

Attribute Description Information gained

RMS Amplitude The square root of the sum of

the squared amplitudes, divided

by the number of live samples

May relate directly to hydrocarbon

indications in the data and other

geologic features which are isolated

from background features by amplitude

response

Relative acoustic

impedance (AI)

A running sum of regularly

sampled amplitude values

calculated by integrating the

seismic trace, passing the result

through a high-pass Butterworth

filter, with a hard-coded cut-off

at (10*sample rate) Hz

may indicate porosity or fluid content

in a reservoir

31

Average energy The squared RMS Amplitude Can be used to map direct hydrocarbon

indicators and/or major lithological

changes in a window

Attenuation The differential loss of high

frequencies relative to low

frequencies as measured above

and below the point of interest

Identifies fracture zones and fluid

movement

Figure 3-16 shows the relative acoustic impedance and the average energy attributes

maps extracted on the interval of 15 milliseconds. Figure 3-17 shows the attenuation and the

RMS amplitude attributes maps extracted on the same interval. The attribute maps shown by

those two figures will be analyzed in the discussion chapter to investigate the lower Cherokee

sands in an effort to find the answers for this study.

Figure ‎3-16 Relative AI and Average Energy maps 15 ms around Mississippian surface

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Figure ‎3-17 Attenuation and RMS Amplitude maps 15 ms around Mississippian surface

33

CHAPTER 4 - Discussions

All maps shown in this section were generated using the following parameters. Attributes

were extracted within an interval of 15 milliseconds around the Mississippian surface, 5

milliseconds below and 10 milliseconds above. This window was chosen to capture the

information of the seismic attributes within the lower Cherokee sand target zone. Higher attribute

values are represented by hotter colors and lower attribute value by cooler colors. As a starting

point, the analysis will be focused on the location of Keith #1 and the surrounding wells, namely

Keith #2 and C. Snodgrass. Similar analysis will be drawn on larger attribute maps covering the

complete region to include the rest of the wells within the seismic coverage.

Figure ‎4-1 Zoomed amplitude and energy maps around Keith #1 area

34

Figure 4-1 shows RMS amplitude map on the left and the average energy map on the

right. Looking at the RMS amplitude map, higher amplitude spots are indicative of hydrocarbon

or geologic features. On the other side, the average energy map, which is the square of the RMS

amplitude, shows a similar but more concentrated pattern. The higher value areas in the energy

map are indicative of greater lithological contrast between the formations within the calculated

window. Therefore, higher energy areas can be translated as areas where the Mississippian

surface, known as dolomite facies, is contrasting with the overlying Cherokee reservoir facies.

And, lower energy areas represent areas where the Mississippian surface and the overlying

Cherokee zone are reflecting a closer match in lithology, i.e. tight or no reservoir areas. Also,

higher amplitude and energy areas can be translated as areas with possible higher hydrocarbon

indications and vise-versa. General observation of the maps shows that all the wells are

positioned on lower amplitude and energy areas.

Figure ‎4-2 Zoomed relative AI and energy maps around Keith #1 area

35

Figure 4-2 shows relative AI map on the left and again the average energy map on the

right. Unlike the other attributes, AI attribute map is interpreted as lower values reflecting better

reservoir quality and higher values indicates poorer reservoir quality. Reservoir quality here

could mean lower porosity and/or no fluid content. Therefore, AI attribute’s values generally

should show the opposite representation of the energy attribute’s values. This means, areas with

higher energy should match with areas with lower AI values and vise-versa. This is based on the

fact that the lower values in AI are reflected by higher amplitude which in return reflects higher

energy values. For areas where this fact does not hold, contribution from other factors may be

possible. For example, areas where bed thickness is less than the dominant wavelength, variation

in thickness would lead to tuning effects resulting in changes in wavelet shape and amplitude.

Those tuning thickness related changes can occur independent of AI variation. Looking at the

maps in the figure, all wells in the area are falling in relatively higher AI and lower energy spots.

Figure ‎4-3 Zoomed attenuation map around Keith #1 area

36

Figure 4-3 shows the attenuation attribute map. Higher attenuation values indicate areas

with possible fractures zones and greater fluid movements. At the same time, lower attenuation

values indicate non-porous areas and poor fluid movements. Therefore, the attenuation map may

indicate areas with higher reservoir quality in terms of porosity and/or permeability. Looking at

the wells in the area, it is evident that all wells are positioned in areas with low attenuation

values which mean poor or no reservoir quality.

Combining information from the extracted attributes maps zoomed on the region of Keith

#1 suggest the following. Keith #2 and C. Snodgrass wells were positioned on low amplitude,

low energy, relatively higher AI and low attenuation areas. This means the wells were targeting

zones with no lithological contrast, no positive hydrocarbon indication, poor reservoir quality,

and the lowest permeability. These observations correlate with the status of the two wells which

were dry holes. On the other hand, Keith #1 well was positioned on an area with a slightly higher

amplitude and energy values, which could be interpreted as slight contrast in lithology and low

hydrocarbon indication. This could explain the presence of the sand signatures shown by the well

logs and the initial production from the well before it was plugged. The poor reservoir quality

and low permeability resulted in low cumulative production, but certainly better than the two dry

holes that were not completed for production at all.

Figure 4-4 shows the average energy map where the rest of the wells. These were

positioned on areas with low energy except for the Wanda Judeen. Figure 4-5 shows the RMS

amplitude map where the wells were positioned on areas with low amplitude, also except for

Wanda Judeen. Figure 4-6 shows relative AI map where the wells were positioned on areas with

relatively higher values. Figure 4-7 shows attenuation map where the wells were positioned on

areas with low attenuation values.

Finally, the extended maps suggest that all the wells within the seismic survey coverage

were targeting zones with no lithological contrast, no hydrocarbon indication, poor reservoir

quality, and poor permeability. Again, these observations correlate with the status of the wells

which show as dry wells. The exception of Wanda Judeen for the energy and amplitude maps

may suggest that the well was positioned on an area of greater contrast in lithology within the

extracted window. Observing and comparing the relative AI and attenuation maps show poor to

no reservoir quality in the area of the well, even though there is a contrast in lithology, which

when correlated to the well status show as a dry well.

37

Figure ‎4-4 Extended average energy map covering all wells within the survey

38

Figure ‎4-5 Extended RMS amplitude map covering all wells within the survey

39

Figure ‎4-6 Extended relative AI map covering all wells within the survey

40

Figure ‎4-7 Extended attenuation map covering all wells within the survey

41

CHAPTER 5 - Conclusions and Recommendations

So, what went wrong in drilling Keith #1? and why was the target sandstone reservoir not

encountered? The answer for these questions was derived from the seismic attributes workflow

that suggested the following: Keith #1 was originally positioned on an area of a greater thickness

and showed doublet reflections on the seismic cross section. These doublets were targeted under

the impression that they may reflect a greater contrast between the underlying Mississippian

surface and the lower Cherokee zone. However, analysis of the seismic attribute maps showed

that these doublets were not due to development of reservoir conditions. Moreover, the isotime

map shows that the thickness of the Cherokee formation at this location is within the tuning

resolution of the seismic data. Hence, the duplex was likely due to tuning as the thickness

approached the resolution. Moreover, the maps showed that Keith #1 was drilled on an area

targeting little lithological contrast, no hydrocarbon indication, poor reservoir quality, and less

permeability. This conclusion applies for all wells drilled within the limits of the seismic survey

coverage. They were all positioned on areas with no incentives of profitable targets.

This study showed that running seismic attributes analysis for similar situations would

provide more knowledge and understanding of geologic features. Since Coral Coast has already

acquired the seismic survey, running this type of workflow would have prevented the drilling

and subsequent costs of the wells in this area. At the same time it would not added any additional

costs since the seismic data was already there.

Finally, Figure 5-1 shows a combination of the four attribute maps used in this study

highlighting an area that could be of interest. The area shows high amplitude, high energy,

relatively low AI, and higher attenuation values. This can be interpreted as higher contrast in

lithology and higher reservoir quality within the extracted zone. However, more analysis needs

to be carried out in order to find out if such an area is considered as a profitable target or not.

42

Figure ‎5-1 combination of the four maps highlighting a possible target

43

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